Enhanced Oil Recovery (abbreviated “EOR”) is a term for those techniques for increasing the amount of hydrocarbon that can be extracted from a reservoir. Enhanced oil recovery is also called improved oil recovery or tertiary recovery (as opposed to primary and secondary recovery). Using EOR, 30 to 60 percent or more of the reservoir's original oil can be extracted, compared with 20 to 40 percent using primary and secondary recovery.
SAGD is the most extensively used EOR for in situ development of the million plus centipoises bitumen resources in the McMurray Formation in the Alberta Oil Sands (Butler, 1991).
A typical SAGD process uses two horizontal wells with one above the other, where the upper one is the steam injector and the lower one is the producer, although steam can be injected into both wells in the startup phase.
The injection well is located directly above the production well, usually a short distance (5 to less than 10 meters). When steam is injected continuously into the injection well, it rises in the formation and forms a steam chamber. With continuous steam injection, the steam chamber continues to grow upward and laterally into the surrounding formation. At the interface between steam chamber and cold oil, steam condenses and the heat is transferred to the surrounding oil. The heated oil becomes mobile and drains together with condensed water to the horizontal producer due to gravity segregation within the steam vapor and liquid (heated) bitumen and steam condensate chamber.
The SAGD technique has many advantages when compared to conventional steam injection methods. In conventional steam injection, oil is displaced to a cold area where its viscosity increases and then the mobility is reduced. SAGD employs gravity as the driving force and the heated oil remains warm and movable when flowing toward the production well.
The performance of the SAGD process is determined by many factors including steam chamber development, the length, spacing and location of the two horizontal wells, heat transfer, ability to effect steam trap control to prevent inefficient production of live steam, heat loss and reservoir properties. Many studies have been done to study those elements that are important for the success of SAGD.
As shown in FIG. 1, the standard SAGD well design employs 800 to 1000 meter slotted liners with tubing strings landed near the toe and near the heel in both an injector 101 and a producer 102 to provide two points of flow distribution control in each well, as illustrated in FIG. 1. Steam is injected into both tubing strings at rates controlled so as to place more or less steam at each end of the completion to achieve better overall steam distribution along the horizontal injector completion.
Likewise, the producer is initially gas-lifted through both tubing strings at rates controlled to provide better inflow distribution along the completion. If steam was injected only at the heel of the injector, and water and bitumen were produced only from the heel of the producer, the tendency would be for the steam chamber to develop only near the heel. This would result in limited rates and poor steam chamber development over much of the horizontal completion.
Typically, SAGD wells are drilled about 5 meters apart vertically to achieve steam trap control whereby a gas (steam vapor)-liquid interface is maintained above the producing well to prevent short-circuiting of steam (e.g., premature breakthrough to the producing well) and undue stress on the producing well sand exclusion media. In order to establish initial communication between the wells, it is typical to circulate steam for 3 to 5 months in each well prior to starting SAGD operation. A 3 to 5 month startup time increases the amount of steam, both water and heat, required before production can begin. This added cost may limit projects available for SAGD production.
There is a need to develop more thermally efficient production techniques while increasing the economic viability of the SAGD process.